Variable annular valve network for well operations

ABSTRACT

A method and system for creating a multi-gradient pressure regime within a wellbore annulus. A plurality of valve subs provided along a drill string with each sub including a port for selectively venting supply fluid from the drill string to the annulus. A valve is coupled to the port to control the supply fluid flow into the annulus. The valve has a stator fixed in relation to the valve sub housing. A rotor is in sealing contact with the stator, the rotor being rotatable with respect to the stator. The stator and rotor each have apertures formed therethrough, so that the rotor may be oriented between a fully shut position in which the stator and rotor apertures are not in alignment and a fully open position in which the stator and rotor apertures are in maximum alignment. The valve allows precise metering between the fully open and shut positions.

TECHNICAL FIELD

The present disclosure relates generally to operations performed and equipment utilized in conjunction with a subterranean well such as a well for recovery of oil, gas, or minerals. More particularly, the disclosure relates to systems and methods for controlling annular flow rate and annular pressure at various points along the wellbore.

BACKGROUND

Generally, when drilling a well, the pore pressure gradient and the fracture pressure gradient increase with the true vertical depth (TVD) of the well. Typically, a mud density (mud weight or MW) for the drilling mud is selected for each drilling interval of a well so that the mud column pressure in the wellbore is greater than the pore pressure, but less than the fracture pressure.

As TVD of the well increases, the mud weight is increased to correspond to the increasing pore pressure gradient and the fracture pressure gradient. If the mud weight falls below the pore pressure, a number of well control issues may arise, such as, for example, a kick. If the mud weight exceeds the fracture pressure, the formation may be fractured resulting in lost circulation and its associated problems.

To prevent drilling mud from damaging the formation by exceeding the fracture pressure, conventional practice typically involves running and cementing a steel casing string in the well. The casing and cement provide structural support to the formation and prevent mud pressure from being applied to the earth above the depth of the casing shoe. The mud weight can then be increased during drilling of the next drilling interval. This process is generally repeated using decreasing bit and casing sizes until the well reaches the planned depth, thereby forming a cased wellbore with casing strings forming a taper along the length of the well. Because well costs are primarily driven by the required rig time to construct the well, each additional casing process will increase the cost of drilling the well. Furthermore, with the conventional steel casing tapered-hole-drilling process, the final hole size that is achieved may not be useable, or optimal. Finally, the casing and cement operations substantially increase well costs. Because of the time and costs associated with running casing strings, it is desirable to extend drilling intervals and maintain an open hole as long as possible before casing the drilled interval.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments are described in detail hereinafter with reference to the accompanying Figures, in which:

FIG. 1 is a graph that shows a pore pressure gradient curve and a fracture gradient curve of an exemplary cased wellbore;

FIG. 2 is a simplified elevation view in partial cross section of a shows a drilling system with a drill string having a plurality of valve subs, according to an embodiment, that may be used to provide multi-pressure-gradient characteristics along the annulus of a wellbore;

FIG. 3 is an enlarged axial cross section of a valve sub of FIG. 2 according to an embodiment; showing a port with a continuously variable controllable valve located therein for selectively transferring fluid through the port;

FIG. 4 is a functional block diagram of the valve sub of FIG. 3;

FIG. 5 is a simplified perspective exploded diagram of a valve of the valve sub of FIG. 3 according to an embodiment, showing a rotor and a stator;

FIG. 6A is an elevation view of the face of the valve of FIG. 5 in a fully open position, showing arcuate teardrop-shaped stator and rotor apertures formed therethrough and oriented in complete alignment;

FIG. 6B is an elevation view of the face of the valve of FIG. 5 in a fully shut position, showing arcuate teardrop-shaped stator apertures in complete alignment with vanes of the rotor;

FIG. 6C is an elevation view of the face of the valve of FIG. 5 in a partially open position, showing arcuate teardrop-shaped stator and rotor apertures in partial alignment for metering flow therethrough; and

FIG. 7 is a flow chart of a method according to an embodiment for detecting downhole conditions based on one or more pressure measurements from one or more pressure sensors in the valve subs of FIG. 2.

DETAILED DESCRIPTION

The foregoing disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Further, spatially relative terms, such as “beneath,” “below,” “lower,” “above,” “upper,” “uphole,” “downhole,” “upstream,” “downstream,” and the like, may be used herein for ease of description to describe one element or feature's relationship to another element(s) or feature(s) as illustrated in the figures. The spatially relative terms are intended to encompass different orientations of the apparatus in use or operation in addition to the orientation depicted in the figures.

As used herein, the term “fluid” includes liquids, gases, liquid-solid slurries and mixtures, emulsions, and combinations thereof.

FIG. 1 is a graph that shows an example of a portion of a pore pressure gradient curve 1 and a fracture gradient curve 3 with example casing setting points 5. The mud densities 7A-C (also called mud weight in the industry) may be set for the given casing setting points 5A-C to result in an annulus fluid 6 pressure above the pore pressure gradient curve 1 but below the fracture gradient curve 3. The casing setting points 5 permit increased open-hole minimum fracture gradients so that a higher mud density can be used in each successive open hole section of the wellbore.

FIG. 2 is a simplified elevation view in partial cross section of a drilling system 100 that may be used to provide multi-gradient flow, velocity and/or pressure characteristics along the annulus 150 of a wellbore 120 according to an embodiment, as described herein. A multi-gradient profile may provide enhanced drilling control, which may in turn allow wellbore 120 to require fewer casing strings. Additionally, a multi-gradient annular profile may result in enhanced hole cleaning and other advantages, as described further below. As used herein, term “multi-gradient” means two or more gradients. Drilling system 100 may be used in vertical wells, non-vertical or deviated wells, multilateral wells, offshore wells, etc.

A drilling rig 102 may be used to extend a drill string 122 into wellbore 120. Drill string 122 may be run all, or partly, into wellbore 120 (which may be completed or in the process of being drilled), thereby defining annulus 150 between drill string 122 and the wall of wellbore 120. Wellbore 120 may be all or partially cased along its length.

The interior of drill string 122 defines an axially extending conduit. Pump 112 may provide a supply fluid 130, such as drilling or other well treatment fluid, downhole through the interior of drill string 122. Annulus 150 may provide a return flow path for the supply fluid 130 that is pumped from surface 101 into the interior of drill string 122. Return fluid 131 is returned to tank 114 at surface 101. Return fluid 131 may then be treated for recirculation by pump 112.

During drilling operations, supply fluid 130 flows from a supply fluid tank 133 down drill string 122 and may exit drill string 122 into wellbore 120 through nozzles in bit 140 which is attached to the bottom of drill string 122. In one example, supply fluid 130 may include a water-based drilling mud. However, drill string 122 may be configured for wellbore activities other than drilling, and may be used without bit 140, in which case supply fluid 130 may exit drill string 122 into wellbore 120 through the bottom of drill string 122, or through at least one other opening in drill string 122. Supply fluid 130 may include weighted drilling mud, a cement slurry, a displacement fluid, a completion fluid, a stimulation fluid, a gravel pack fluid, and any other suitable wellbore fluid.

In some embodiments, one or more flow return devices 106 may be used at or near surface 101 for controlling flow of return fluid 131 from annulus 150, including conventional blow out preventers, rotating control devices, fixed or adjustable chokes, and the like. A pump or other fluid source (not specifically illustrated) may at times be hydraulically coupled to the annulus for purposes of circulating additional fluid down into annulus 150 or pressurizing annulus 150.

One or more sensors 104 may be provided at or near surface 101 for making measurements of one or more properties of supply fluid 130 and/or return fluid 131 and may include a pressure sensor, flow rate sensor, or other suitable sensor. Sensor(s) 104 may be located at a standpipe, pump 112, upstream or downstream of a surface choke, and/or on a riser or other conduits which transport supply or return fluid 130, 131, for example.

Drill string 122 may include a drill pipe section 116 and a bottom hole assembly 117. Drill string 122 may include standard drill pipe, drill collars, wired drill pipe, wired drill collars, coiled tubing, and combinations thereof. Drill pipe section 116 may include drill pipe joints 118 that may include wired pipe to provide bi-directional communication of data and/or power between surface 101 and various downhole devices.

Bottom hole assembly 117 may be coupled to the bottom of drill pipe section 116 and may include a measurement-while-drilling tool 145 having one or more sensors, a drilling motor 144, a rotary steerable device, drill bit 140, drill collars, stabilizers, reamers, and other common bottom hole assembly elements. Bottom hole assembly 117 may be of relatively short length, for example 30 to 300 feet, as compared to the overall drill string 122, which may be several thousand feet of length.

Bottom hole assembly 117 may interface with a communications link to or through the drill pipe section 116, for high data rate communication to and from surface 101. Some implementations may include a communication network along part, or all, of drill pipe section 116, with nodes (for data acquisition, receipt, and/or handling) at one or more locations along drill pipe section 116 above bottom hole assembly 117. Such a network may use one or more communication media or techniques including but not limited to: wired pipe, mud pulse telemetry, low frequency (under 1000 Hz) electromagnetic telemetry (“EM telemetry”), RF telemetry, acoustic telemetry, hard wired telemetry, fiber optic telemetry, and combinations thereof. As used herein, “hard wired” refers to one or more conductors providing a continuous electrical path over some length. Examples of hard wired implementations include wired pipe, wireline conveyed down a flow path of drill string, a wireline conveyed down the outside of a drill string, or combinations thereof. Hard wired implementations may include metal-to-metal connections, inductive connections, and other connections between pipe joints, and/or at other locations along the length of drill string 122.

Drilling system 100 may include a central controller 103, which may be located along drill string 122, at the sea floor (not illustrated), or at surface 101. Central controller 103 may also be located at least in part at a location remote from wellbore 120, for example at a remote data center. Such a remote data center may be linked to the well site by wire or wireless data links. Central controller 103 may receive signals from downhole using suitable telemetry techniques, including mud pulse telemetry, low frequency (under 1000 Hz) electromagnetic telemetry (“EM telemetry”), RF telemetry, acoustic telemetry, hard wired telemetry, fiber optic telemetry, and combinations thereof.

Central controller 103 may include one or more processors in data communication with computer memory for containing instructions and computer models for controlling the operations described below. The computer memory may include non-volatile memory.

Central controller 103 may include a user interface, which may include one or more of graphical or numeric output displays 105 that may provide a log display of pressures, flow rates, flow velocities, or other parameters versus depth and/or time. Other outputs displayed may include open/shut/throttling status of valve subs 124 (described hereinafter) and results of models and/or processing of downhole data. As is common, a keyboard and/or mouse may be used for user input.

According to an embodiment, a plurality of valve subs 124 are disposed at axially-spaced locations along drill string 122. In one example, valve subs 124 are spaced approximately every 90-100 feet along the drill string 122. Any other suitable spacing may be used. Valve subs 124 may be spaced along drill string 122 for coverage of one or more particular wellbore sections, such as a vertical section, slant, curve, and/or horizontal section.

One or more valve subs 124 may be located within bottom hole assembly 117. One or more valve subs 124 may be located separate from and above the bottom hole assembly 117 along all or a portion of drill pipe section 116. Such drill pipe section 116 valve subs 124 may be located in between sections of conventional drill pipe, or in between sections of wired drill pipe. Valve subs 124 define an internal axial flow path to pass supply fluid 130 onward through drill string 122 to bit 140. Each valve sub 124 may be a unitary sub, or a combination of subs which are coupled within drill string 122.

Each valve sub 124 includes a valved port, described in greater detail below, that selectively and controllably vents supply fluid 130 from drill string 122 into annulus 150 to adjust the pressure, velocity, or flow profile in annulus 150. That is, each valve sub 124 may controllably dispense a portion of supply fluid 130 into annulus 150 to mix with return fluid 131 and result in an increased annular return fluid flow at the location of the valve sub. By so adjusting the pressure profile in annulus 150, a stepped or multi-gradient flow rate, velocity, and/or pressure profile may be generated along the annulus return flow path despite a constant flow rate provided by pump 112.

Drill string 122 may have a change in size along its length. For example, drill string 122 may have a larger internal diameter near the top end to accommodate more flow and may have a smaller internal diameter near the bottom end where the size of wellbore 120 is smaller and lower flow rates are expected. Such a drill string 122 may be a tapered drill string, but the taper may not be continuous but rather include one or more step changes in size at particular points along the drill string.

Further, valve subs 124 and/or their valve ports along drill string 122 can be adjusted in size and/or design to be optimized for lower flow rates to match the decrease in flow of supply fluid 130 through drill string 122 as the flow progresses past each valve sub 124 venting supply fluid 130 into annulus 150. For example larger valve subs 124 and/or larger ports may exist near the upper portion of drill string 122 and smaller valve subs 124 and/or smaller ports may exist near the lower portion of drill string 122.

FIG. 3 is an axial cross section of valve sub 124 according to an embodiment. FIG. 4 is a functional block diagram of various components of the valve sub 124 of FIG. 3. As shown in FIGS. 3 and 4, valve sub 124 may include a tubular housing 126 that defines an interior 127, which is in fluid communication with the interior of drill string 122 (FIG. 2). Valve sub 124 includes a controllable valve 158 disposed so as to control fluid communication through port 159, which selectively fluidly couples interior 127 with annulus 150. Valve 158 may provide infinitely variable flow adjustment between fully shut and fully open positions. An actuator 155 operates valve 158. A valve position sensor 173 is coupled to valve 158 so as to monitor the valve position.

Actuator 155 may include a servo, stepper motor, solenoid or other electric device capable of providing motion and position control to valve 158. Alternatively, actuator 155 may be a hydraulic actuator, for example a hydraulic cylinder. Actuator 155 may include a biasing element (not illustrated) such a spring, or a structure such as piston, to provide some or all the force required for motion of valve 158. The biasing element may be coupled to valve position sensor 173.

Valve sub 124 may also include a valve position sensor 173, at least one sensor 157, a communication transmitter/receiver 156, a valve sub controller 170, and a power source 180. Transmitter/receiver 156, sensor 157, controller 170, and power source 180 may be located within housing 126, or one or more of the transmitter/receiver 156, sensor 157, controller 170, and power source 180 may be physically remote (for example up or down drill string 122) from the housing 126, though still operably coupled (for example by wires) to the other elements of valve sub 124 as required for the operation described herein.

Transmitter/receiver 156 may include a single transceiver performing both transmit and receive functions, or, alternatively may include separate devices for each function. Transmitter/receiver 156 may enable communication between various valve subs 124 within drill string 122 (FIG. 2). Transmitter/receiver 156 may also enable communication between valve sub 124 and central controller 103. Communications, between two or more valve subs 124 or between valve sub 124 and central controller 103, may be by mud pulse telemetry, EM telemetry, RF telemetry, acoustic telemetry, optical telemetry, hard wired telemetry, and combinations thereof.

Sensors 157 may include pressure sensors and/or flow or velocity sensors, which may be arranged for measuring fluid properties within interior 127, within annulus 150, or both. Other sensors types may also be located in valve sub 124 and may be used to determine local properties of the supply and return fluid 130, 131, including but not limited to, temperature, density, phase, resistivity, pH, viscosity, and chemical composition. Signals from sensors 157 may be analog or digital.

In some embodiments, sensors 157 may be commercially available pressure sensors that convert pressure to one or more signals. Such pressure sensors may include strain gauge type devices, quartz crystal devices, fiber optical devices, or other devices used to sense pressure.

In certain implementations, sensors 157 may be oriented to measure one or more static pressures. For example, sensors 157 may be oriented perpendicular to streamlines of flow of supply or return fluid 130, 131. Sensors 157 may measure stagnation pressure if oriented to face, or partially face, into the flow of supply or return fluid 130, 131. In certain implementations, sensors 157 may use pitot tubes or a shallow ramping ports to orient the sensors to face, or partially face, into the fluid flow. The measurement accuracy of the stagnation pressure may vary depending on a degree of boundary layer influence.

Valve sub controller 170 may include a processor 176. Processor 176 is in data communication with input/output (“I/O”) circuitry 175 and computer memory 177, which may include non-volatile memory. I/O circuitry 175 powers and interfaces with valve position sensor 173, sensors 157, valve actuator 155, and transmitter/receiver 156. Processor 176 interprets signals from sensors 157 and controls the state of valve actuator 155 according to programmed instructions stored in memory 177 or from commands received from central controller 103, or another valve sub 124 along drill string 122, via transmitter/receiver 156.

In some embodiments, valve sub controller 170 receives input signals from valve position sensor 173 to monitor the position of valve 158. Valve sub controller 170 may control the position of valve 158 using closed loop control based in the input signals from valve position sensor 173. Alternatively, valve sub controller 170 may exercise open loop control of valve 158.

Computer models 174 stored in memory 177 may be used to determine the appropriate desired fluid property at the location of valve sub 124. Valve sub controller 170 may actuate valve 158 to vent supply fluid 130 into the return fluid stream to adjust the pressure, flow rate or velocity of the return fluid stream in annulus 150 at selected locations along wellbore 120 to match requirements of compute model 174. According to an embodiment, valve sub 124 may act autonomously to adjust the return fluid properties as the fluid passes valve sub 127 according to computer model 174 stored in the memory 177. In this regard, valve sub controller 170 may be in control communication with a pumping system, which may include one or more supply fluid tanks, such as tanks 131 and 114, pump 112, and related valves or valve systems in order to direct additional drilling fluids of a select density determined based on sensors 157 into drillstring 122 for release by the appropriate valve 150 at a desired depth.

Power source 180 may include a downhole electrical generator 181. A turbine 182, driven by supply fluid 130 flowing through drill string 122, may be coupled to generator 181 for driving generator 181. Turbine 182 may also be coupled to valve sub controller 170 and function as a sensor 157 for measuring a flow of supply fluid 130 passing by turbine 182. Electric power may be supplied from surface 101 via conductors within drill string 122 or wired pipe, as previously described. Additionally or alternatively, power source 180 may also include a battery and or storage capacitors (not illustrated).

Flow port 159 may be configured to direct fluid in a radial direction towards the wellbore wall. In some embodiments, flow port 159 may include a directional nozzle (not illustrated) that directs flow in an uphole or downhole direction so as to control fluid impingement on the wellbore wall or to otherwise minimize return fluid 131 turbulence during release of supply fluid 130 into the annulus 150. The nozzle may also be configured to direct fluid in a manner to control flow jetting, flow mixing, to agitate and mix materials, for example, cuttings entrained in return fluid 131, or to remove filter cake from the wall of wellbore 120, for example. Accordingly, the nozzle may be configured to focus the exiting fluid in a narrow jet, or in a more broadly dispersed flow.

FIGS. 5-6C illustrate one configuration of valve 158 and the operation thereof according to one or more embodiments. Referring to FIGS. 3 and 5-6C, valve 158 is coupled to port 159 disposed so as to control fluid flow through the port. For example, as shown, valve 158 may be sealingly disposed within port 159.

Valve 158 has a stator 183, which may have a circular disk or hemispherical shape, for example, and which is fixed in relation to housing 126. Stator 183 includes stator apertures 191 formed therethrough for providing an isolable flow path through valve 158. Stator apertures 191 are interleaved by stator vanes 190. Similarly, valve 158 has a rotor 184, which may have a circular disk or hemispherical shape that corresponds to stator 183. Rotor 184 rotatively engages and is dynamically sealed against stator 183. Rotor 184 includes rotor apertures 193 formed therethrough for providing an isolable flow path through valve 158. Rotor apertures 193 are interleaved by rotor vanes 194. Valve position sensor 173 may be coupled to rotor 184.

As shown in FIGS. 6A-6C, in one or more embodiments, stator 183 may have arcuate teardrop-shaped stator vanes 190 and corresponding arcuate teardrop-shaped stator apertures 191. In the illustrated embodiment, two vanes 190 and apertures 191 are illustrated, however, a differing number and differing shaped of stator vanes 190 and/or stator apertures 191 may be provided. Likewise, rotor 184 is shown with two arcuate teardrop-shaped rotor vanes 193 and two arcuate teardrop-shaped rotor apertures 194, but a differing number and/or shapes may be provided.

Actuator 155 is connected to rotor 184 and is operable to rotate rotor 184 with respect to stator 183 between a fully open position (FIG. 6A), in which stator apertures 191 and rotor apertures 193 are maximally aligned, and fully shut position (FIG. 6B), in which stator apertures 191 are covered and isolated by rotor vanes 194. Between the fully open and fully shut positions, as shown in FIG. 6C, the effective aperture through valve 158, which is defined as the intersecting area of stator apertures 191 and rotor apertures 193, is continuously variable and determined by the position of rotor 184 with respect to stator 183. Such an arrangement allows precise control for metering flow from interior 127 of valve sub 124 to annulus 150.

As illustrated in FIG. 3, actuator 155 may be coupled to rotor 184 via a drive shaft 185, which may include bevel gears 186. However, actuator 155 may be directly connected to rotor 184 or connected via another suitable linkage.

Referring back to FIGS. 2-4, in some embodiments, wired drill pipe may be used to provide a high speed communications channel along the network of valve subs 124 and optionally may provide power to valve subs 124 as described above. Wires may transit drill string 122 via tubing running along the interior wall of the drill pipe, or via tubing centralized in the drill pipe. Alternatively, a wireline and/or optical fiber may be run down the interior of drill string 122 to facilitate the high speed communications. In yet another alternative, an electrically conductive wired pipe network may be employed, which may include inductive couplers at drill pipe connections. In yet another alternative, a light conductive fiber optic wired pipe network may be employed, which may include optical couplers at drill pipe connections.

In some embodiments, each valve sub 124 may act autonomously. Alternatively, each valve sub 124 along drill string 122 may communicate with central controller 103 and/or at least one other valve sub 124, using suitable telemetry techniques, to transmit data indicating the state of its associated valve 158. Each valve sub 124 may then recalculate any adjustment necessary at its location along drill string 122 according to computer model 174 based at least in part on the data and/or information received from other valve subs 124 and/or central controller 103.

In other embodiments, using a high speed communication channel, control of one or more valve subs 124 may be by central controller 103 and settings for each such valve sub continuously transmitted to each affected sub, periodically transmitted to each affected sub, transmitted as need is determined by central controller 103 and/or by a human operator.

In other embodiments, a valve sub controller 170 of a particular valve sub 124 may be designated as a master controller for a network of valve subs 124. Each valve sub 124 may be identified with an identification number and its known position along drill string 122. Pressure measurement data may be transmitted by other valve subs 124 to the downhole master controller or central controller 103, where it may be converted into a pressure gradient profile along the portion of wellbore 120 where the measurements are made. The data may be compared to predicted or allowable pressure gradient values and/or predictive models located in the downhole master controller or central controller 103, as described in greater detail below. Appropriate valve subs 124 may then be actuated to vent supply fluid 130 to annulus 150 to achieve or maintain a desired fluid pressure gradient.

FIG. 7 is a flow chart outlining a method for annular pressure control according to an embodiment. One or more of valve subs 124 may be operated to detect downhole conditions based on one or more measurements from one or more sensors 157 according to the method of FIG. 7. A downhole condition may include any regular or irregular, static or dynamic, condition or event along a round-trip fluid path. Example downhole conditions may include, but are not limited to, one or more of the following: Annulus pressure, drill string pressure, annulus flow rate, a flow restriction, a cuttings build-up, a wash-out, and an influx. A cuttings build-up may be identified as an annulus obstruction over an interval. A flow restriction may include that from swelling shale.

The processing and determining of a downhole condition may be done either by a central controller 103, a valve sub controller 170, and/or human at surface 101. For example, a particular valve sub controller 170 may determine if there is an increased pressure gradient over an interval. If so, and if the interval is in a particular section of wellbore 120 known to be susceptible to cuttings build-up, such as a “knee” section, valve sub controller 170 may open valve 158 via actuator 155 to increase annular fluid flow at that location. Accordingly, at least one valve sub 124, and in some cases multiple valve subs 124, may operate simultaneously or sequentially to agitate and mobilize cuttings in wellbore 120, for example in one or more of a horizontal section or the “knee” of the curve section to at least partially alleviate this build up condition.

Referring to FIG. 7, at step 205, valve sub controller 170 determines a set of expected pressure values. Creating the set of expected pressure gradient values may include receiving one or more expected pressures from an external source (e.g., a user, a database, or another processor). Creating the expected-pressure gradient set may include accessing simulation results such as modeling results stored in computer memory of the system. The modeling to create the expected pressure values may include hydraulics modeling.

Hydraulics modeling may consider one or more of the following: Properties of the wellbore and drill string, fluid properties, previous pressure measurements from the wellbore or another wellbore, or other measurements. In some implementations an expected-pressure gradient set may be created by copying one or more values from a measured-pressure set. In other implementations an expected-pressure gradient set may be created by using values from a measured-pressure gradient set and adjusting or operating upon the values in accordance with an algorithm or model. Some implementations utilizing measured-pressure gradient sets in the creation of expected-pressure gradient sets may use measured-pressure gradient sets from a recent time window, an earlier time window, or multiple time windows. Certain example expected-pressure gradient sets may be derived from trend analysis of measured-pressure gradient sets, such trends being observed or calculated in reference to for example elapsed time, circulation time, drilling time, depth, another variable, or combinations of variables.

The set of expected pressure values may include one or more pressure values at one or more depths in the wellbore. The depths may be locations of interest within wellbore 122. A set of expected values may be provided or determined corresponding to all or a portion of the fluid flow path within the wellbore. The set of expected pressure values may represent one or more pressure profiles. A pressure profile may include a set of two or more pressures, and a set of two or more depths, or ranges of depths, where each pressure corresponds to a depth or a range of depths. The pressure profiles may exist, may be measurable, and may be modeled along the continuum of fluid or fluids in wellbore 120 along one or more fluid flow paths within wellbore 120 and along one or more wellbore/wellbore hydraulic paths or circuits.

Example pressure gradient profiles may include one or more hydrostatic profiles. Other example pressure gradient profiles include one or more static pressure gradient profiles that may include losses. The losses may include frictional losses or major losses, where major losses are typically associated with cross sectional area changes (e.g., drill bit nozzles, mud motors, and surface chokes). Other example pressure gradient profiles may include stagnation pressure profiles. The stagnation pressure gradient profiles may be related to flow velocity. Example pressure gradient profiles may include arithmetic or other combinations or superposition of profiles.

Valve sub controller 170 may model or be provided hydrostatic pressures, hydrostatic profiles, and changes in hydrostatic pressure within the drill string or the wellbore 120. Valve sub controller 170 may model or be provided with frictional pressures, frictional profiles, frictional losses, or frictional changes within the drill string or the wellbore 120. Valve sub controller 170 may model or be provided with one or more stagnation pressures, stagnation pressure profiles, stagnation pressure losses, or stagnation pressure changes within drill string 122 or wellbore 120.

Valve sub controller 170 may consider one or more factors affecting pressure including the dimensions of drill string 122 (e.g., inner and outer diameters of joints or other portions of the drill pipe and other drill string elements) and dimensions of wellbore 120. Valve sub controller 170 may also consider one or more depths corresponding to one or more measured pressures within the wellbore 120. Valve sub controller 170 may consider drilling fluid properties (e.g., flow rates, densities, yield point, viscosity, or composition), one or more major loss sources (e.g., drill bit nozzles, mud motors, and surface chokes), and whether one or more portions of the wellbore 120 are cased or open hole.

Valve sub controller 170 may be provided with or calculate one or more depths when calculating the expected pressure gradient. The depths may include one or more of the following: True vertical depth (i.e., only the vertical component of the depth), measured depth (i.e., the directionless distance of wellbore 120), and round-trip depth. In general, round-trip depth is the directionless distance traveled by the circulating fluid.

At step 210, valve sub controller 170 receives one or more pressure measurements from sensor(s) 157. At steps 215 and 220, valve sub controller 170 may create a measured-pressure set from the pressure measurements received and may determine one or more measured-pressure gradients along wellbore 120. Measurements may be taken while drilling, during circulation of fluid in wellbore 120 with drill bit 140 (FIG. 2) off bottom, during a period of flow stoppage, or while running or tripping the drill string, for example. During any of these activities, a fluid property, such as annular pressure, of any particular section of the drill string or along the entire drill string, may be measured to create a measured-pressure gradients versus depth along wellbore 120.

Thereafter, at step 225, valve sub controller 170 may compare the measured pressure gradient profile with the expected pressure gradient profile to detect a downhole condition. If valve sub controller 170 detects a downhole condition, at step 235 it may identify, locate, and characterize the downhole condition. In response to the downhole condition, at step 240, valve sub controller 170 may control valve 158 via actuator 155 to vent supply fluid 130 from interior 127 of valve sub 124 to annulus 150. Valve sub controller 170 may also transmit its action to other valve subs 124 or to central controller 103.

Regardless of whether valve sub controller 170 detects a particular downhole condition, it may modify the expected-pressure gradient set at step 245. For example, while drilling wellbore 120, valve sub controller 170 may update the expected pressure gradient to reflect changes in wellbore 120. Valve sub controller 170 may change the expected-pressure set to reflect drilling progress (i.e., increasing depth). Valve sub controller 170 may alter the expected pressure gradient to account for one or more known or unknown drilling process events or conditions. Changes to the pressure profile may be consistent or inconsistent with modeling, forecasts, or experience. Alternatively, surface processor 103 may change the expected set of pressure values and transmit them to valve sub controller 170. The process thereafter may return to step 210 and be repeated.

In summary, a valve sub, a system for use in a wellbore, and a method for creating a multi-gradient pressure within a wellbore annulus have been described.

Embodiments of the valve sub may have: A tubular housing; a port formed through a wall of the housing fluidly coupling an interior of the housing to an exterior of the housing; a valve coupled to the port disposed so as to control a fluid flow through the port, the valve having a stator fixed in relation to the housing with a stator aperture formed therethrough and a rotor in sealing contact with the stator with a rotor aperture formed therethrough, the rotor being rotatable with respect to the stator between a fully shut position in which the stator aperture and the rotor aperture are not in alignment and a fully open position in which the stator aperture and the rotor aperture are in maximum alignment; and a valve sub controller coupled to the valve operable to control an orientation of the rotor with respect to the stator.

Embodiments of the system for use in a wellbore may have: A rig; a drill string extending from the rig; at least two valve subs disposed along the drill string, each the valve sub having a tubular housing defining an interior that is fluidly coupled with an interior of the drill string; a port formed through the housing of each the valve sub, each the port fluidly coupling the interior of the drill string to an exterior of the drill string; and a valve coupled to each the port, respectively, so as to selectively control fluid flow through the port, each the valve having a stator with a stator aperture formed therethrough and a rotor in sealing contact with the stator with a rotor aperture formed therethrough, the rotor being rotatable with respect to the stator between a fully shut position in which the stator aperture and the rotor aperture are not aligned and a fully open position in which the stator aperture and the rotor aperture are maximally aligned.

Embodiments of the method for creating a multi-gradient pressure within a wellbore annulus may generally include: Determining a measured pressure gradient within the wellbore by measuring annular pressure within a wellbore at a first depth and at a second depth different than the first depth; and actuating a first valve release supply fluid from a drill string into the wellbore annulus, wherein fluid flow through the first valve is selectively controlled by rotating a rotor relative to a stator to permit the supply fluid to pass through an aperture into the wellbore annulus.

Any of the foregoing embodiments may include any one of the following elements or characteristics, alone or in combination with each other: An actuator mounted to the housing and coupled between the rotor and the valve sub controller so as to selectively rotate the rotor with respect to the stator; a sensor mounted to the housing and coupled to the valve sub controller; a generator mounted to the housing and coupled to the valve sub controller, the generator arranged to generate electrical power from a fluid flow through the interior of the housing; a turbine disposed in the interior of the housing and coupled to the generator for turning the generator; the turbine is coupled to the valve sub controller and arranged for providing a signal proportional to the fluid flow through the interior of the housing; a transmitter/receiver mounted to the housing and coupled to the valve sub controller; the stator includes first and second stator apertures each having an arcuate teardrop shape; the rotor includes first and second rotor apertures each having an arcuate teardrop shape; the stator has a generally planar surface; the rotor has a generally planar surface; at least one valve sub controller and at least actuator coupled to each the valve and operable to control an orientation of the rotor with respect to the stator of each the valve; at least one sensor coupled to the at least one valve sub controller; at least one generator coupled to the at least one valve sub controller, the at least one generator arranged to generate electrical power from a fluid flow through the interior of the drill string; at least one turbine coupled to the at least one generator for turning the at least one generator; the at least one turbine is coupled to the at least one valve sub controller and arranged for providing a signal proportional to the fluid flow through the interior of the drill string; an actuator coupled to each the valve and operable to position the rotor with respect to the stator of each the valve; a valve sub controller coupled to each the actuator and operable to control each the actuator; a transmitter/receiver coupled to each the valve sub controller, the transmitter/receiver of a first valve sub controller operable to communicate with the transmitter/receiver of a second valve sub controller; a pressure sensor carrier coupled to each the valve sub controller; a central controller coupled to the valve sub controllers; a pumping system fluidly coupled to the drill string and in communication with at least one the valve sub controller, the at least one the valve sub controller operable to control the pumping system; a supply fluid tank fluidly coupled to the pump; the stator of each of the first and second valves includes first and second stator apertures each having an arcuate teardrop shape; the rotor of each of the first and second valves includes first and second rotor apertures each having an arcuate teardrop shape; the stator of each of the first and second valves has a generally planar surface; the rotor of each of the first and second valves has a generally planar surface; at least the measured annular pressure at the first and second depths define a measured pressure set; the first valve is located at the first depth; actuating the first valve results in an adjusted pressure gradient in the wellbore that is different that the measured pressure gradient; actuating a second valve at the second depth to release supply fluid from the drill string into the wellbore annulus, wherein fluid flow through the valve is selectively controlled by rotating a rotor relative to a stator to permit the supply fluid to pass through an aperture into the wellbore annulus; creating an expected pressure set along at least a portion of the wellbore annulus; determining a calculated pressure gradient from the expected pressure set; comparing the measured pressure gradient to the calculated pressure gradient; actuating the first valve based on the comparison of the measured pressure gradient to the calculated pressure gradient; determining a downhole condition based on the comparison of the measured pressure gradient to the calculated pressure gradient; identifying a location of the downhole condition based on the comparison of the measured pressure gradient to the calculated pressure gradient; and modifying the expected pressure set based on actuating the first valve.

The Abstract of the disclosure is solely for providing a way by which to determine quickly from a cursory reading the nature and gist of technical disclosure, and it represents solely one or more embodiments.

While various embodiments have been illustrated in detail, the disclosure is not limited to the embodiments shown. Modifications and adaptations of the above embodiments may occur to those skilled in the art. Such modifications and adaptations are in the spirit and scope of the disclosure. 

What is claimed:
 1. A valve sub for use along a drill string within a wellbore, comprising: a tubular housing; a port formed through a wall of said housing fluidly coupling an interior of said housing to an exterior of said housing; a valve coupled to said port disposed so as to control a fluid flow through said port, said valve having a stator fixed in relation to said housing with a stator aperture formed therethrough and a rotor in sealing contact with said stator with a rotor aperture formed therethrough, said rotor being rotatable with respect to said stator between a fully shut position in which said stator aperture and said rotor aperture are not in alignment and a fully open position in which said stator aperture and said rotor aperture are in maximum alignment; and a valve sub controller coupled to said valve operable to control an orientation of said rotor with respect to said stator.
 2. The valve sub of claim 1 further comprising: an actuator mounted to said housing and coupled between said rotor and said valve sub controller so as to selectively rotate said rotor with respect to said stator.
 3. The valve sub of claim 1 further comprising: a sensor mounted to said housing and coupled to said valve sub controller.
 4. The valve sub of claim 1 further comprising: a generator mounted to said housing and coupled to said valve sub controller, said generator arranged to generate electrical power from a fluid flow through said interior of said housing.
 5. The valve sub of claim 4 further comprising: a turbine disposed in said interior of said housing and coupled to said generator for turning said generator.
 6. The valve sub of claim 5 wherein: said turbine is coupled to said valve sub controller and arranged for providing a signal proportional to said fluid flow through said interior of said housing.
 7. The valve sub of claim 1 further comprising: a transmitter/receiver mounted to said housing and coupled to said valve sub controller.
 8. The valve sub of claim 1 wherein: said stator includes first and second stator apertures each having an arcuate teardrop shape; and said rotor includes first and second rotor apertures each having an arcuate teardrop shape.
 9. The valve sub of claim 8 wherein: said stator has a generally planar surface; and said rotor has a generally planar surface.
 10. A system for use within a wellbore, comprising: a rig; a drill string extending from said rig; at least two valve subs disposed along said drill string, each said valve sub having a tubular housing defining an interior that is fluidly coupled with an interior of said drill string; a port formed through the housing of each said valve sub, each said port fluidly coupling said interior of said drill string to an exterior of said drill string; and a valve coupled to each said port, respectively, so as to selectively control fluid flow through said port, each said valve having a stator with a stator aperture formed therethrough and a rotor in sealing contact with said stator with a rotor aperture formed therethrough, said rotor being rotatable with respect to said stator between a fully shut position in which said stator aperture and said rotor aperture are not aligned and a fully open position in which said stator aperture and said rotor aperture are maximally aligned.
 11. The system of claim 10 further comprising: at least one valve sub controller and at least actuator coupled to each said valve and operable to control an orientation of said rotor with respect to said stator of each said valve.
 12. The system sub of claim 11 further comprising: at least one sensor coupled to said at least one valve sub controller.
 13. The system of claim 11 further comprising: at least one generator coupled to said at least one valve sub controller, said at least one generator arranged to generate electrical power from a fluid flow through said interior of said drill string.
 14. The system of claim 13 further comprising: at least one turbine coupled to said at least one generator for turning said at least one generator.
 15. The system of claim 14 wherein: said at least one turbine is coupled to said at least one valve sub controller and arranged for providing a signal proportional to said fluid flow through said interior of said drill string.
 16. The system of claim 10 further comprising: an actuator coupled to each said valve and operable to position said rotor with respect to said stator of each said valve; a valve sub controller coupled to each said actuator and operable to control each said actuator; a transmitter/receiver coupled to each said valve sub controller, the transmitter/receiver of a first valve sub controller operable to communicate with said transmitter/receiver of a second valve sub controller; and a pressure sensor carrier coupled to each said valve sub controller.
 17. The system of claim 16 further comprising: a central controller coupled to said valve sub controllers.
 18. The system of claim 16 further comprising: a pumping system fluidly coupled to said drill string and in communication with at least one said valve sub controller, said at least one said valve sub controller operable to control said pumping system; and a supply fluid tank fluidly coupled to said pump.
 19. The system of claim 10 wherein: the stator of each of said first and second valves includes first and second stator apertures each having an arcuate teardrop shape; and the rotor of each of said first and second valves includes first and second rotor apertures each having an arcuate teardrop shape.
 20. The system sub of claim 19 wherein: the stator of each of said first and second valves has a generally planar surface; and the rotor of each of said first and second valves has a generally planar surface.
 21. A method for creating a multi-gradient pressure within a wellbore annulus, comprising: determining a measured pressure gradient within said wellbore by measuring annular pressure within a wellbore at a first depth and at a second depth different than the first depth; and actuating a first valve release supply fluid from a drill string into the wellbore annulus, wherein fluid flow through the first valve is selectively controlled by rotating a rotor relative to a stator to permit the supply fluid to pass through an aperture into the wellbore annulus.
 22. The method of claim 21 wherein: at least said measured annular pressure at the first and second depths define a measured pressure set.
 23. The method of claim 21 wherein: said first valve is located at said first depth; and actuating said first valve results in an adjusted pressure gradient in said wellbore that is different that said measured pressure gradient.
 24. The method of claim 23 further comprising: actuating a second valve at the second depth to release supply fluid from said drill string into the wellbore annulus, wherein fluid flow through the valve is selectively controlled by rotating a rotor relative to a stator to permit the supply fluid to pass through an aperture into the wellbore annulus.
 25. The method of claim 22 further comprising: creating an expected pressure set along at least a portion of said wellbore annulus; determining a calculated pressure gradient from the expected pressure set; comparing the measured pressure gradient to the calculated pressure gradient; and actuating said first valve based on the comparison of the measured pressure gradient to the calculated pressure gradient.
 26. The method of claim 25 further comprising: determining a downhole condition based on the comparison of the measured pressure gradient to the calculated pressure gradient; and identifying a location of said downhole condition based on the comparison of the measured pressure gradient to the calculated pressure gradient.
 27. The method of claim 25 further comprising: modifying the expected pressure set based on actuating said first valve. 